Thursday, August 8, 2019

Finding the Cracks in Master's Creek

Murray A-1 is a dual-lateral well drilled by OXY USA Inc. in the Cretaceous Austin Chalk formation, located in the Master's Creek field, Rapides Parish, Lousiana, USA. The Austin Chalk is a low-permeability formation that produces hydrocarbons from fractures, when present. Indications of fractures were seen from cuttings and gas shows obtained by mud loggers on a previous well. The intention was to drill this well perpendicular to the fracture planes to intersect multiple fractures and maximize production.

OXY wanted to record borehole images in the reservoir section for fracture evaluation. Fracture orientation would show if the well trajectory was optimal for intersecting the maximum number of fractures. Knowledge of fracture frequency, size and location along the horizontal section could be useful for future completion design, reservoir engineering and remedial work.

Ideally, the wireline FMI Fullbore Formation MicroImager tool would have been run, but practical considerations precluded this option. Wireline tools can be conveyed downhole by drillpipe or by coiled tubing in high-deviation or horizontal wells, but pressure-control requirements prevented the use of drillpipe conveyance in this case and coiled tubing was considered too costly. Also, calculations showed that helical coiled tubing lockup would occur before reaching the end of the long horizontal section. So OXY decided to try the RAB tool. 

 The first lateral well was drilled due north to cut assumed fracture planes at right angles. During drilling , images were recorded over about 2000 ft [600 m] of the 8 1/2 inch. horizontal hole. After each bit run the data were dumped to a surface workstation and examined using Fracview software.

Although the resolution of the RAB tool is not high enough to see microfractures, several individual major fractures and clusters of smaller fractures were clearly seen, providing enough evidence that the well trajectory was nearly perpendicular to the fracture trend.

Images of California 

Complex tectonic activity in southern California, USA, has continued throughout the Tertiary period to the present time. This activity influences offshore Miocene reservoirs where folding and tilting affect reservoir structure. Production is from fractured, cherty, dolomitic and siliceous zones through wellbores that are often drilled at high angle.

Wireline logs are run for formation evaluation and fracture and structural analysis-although in some cases they have to conveyed downhole on the TLC Tough Logging Conditions system.

The CDR Compensated Dual Resistivity tool was used to record resistivity and gamma ray logs for correlation while drilling. The oil company wanted to evaluate using the RAB tool primarily for correlation, but also wanted to assess the quality of images produced. In fact, it was the images that, in the end, generated the most interest.

Good-quality FMI logs were available, allowing direct comparison with RAB images. Both showed large-scale events, such as folded beds, that were several feet long, as well as regular bedding planes. However, beds less than a few inches thick were not seen clearly by RAB images. 

 Analysis of cores indicated wide distribution of fractures throughout the reservoir with apertures varying from less than 0.001 in. to 0.1 in. . The button electrodes that produce RAB images are large in comparison - 1 in. in diameter. However, even with low-resisitivy contrast across the fractures, the largest fractures or densest groups of fractures that appear on the FMI images were seen on the RAB images. The RAB tool could not replace FMI data.

What intrigued the oil company , however, was the possibility of calculating dips from RAB images. If this were successful, then the RAB tool could help resolve structural changes, such as crossing a fault, during drilling. The suggestion was taken up by Anadrill. With commercial software, dips were calculated from RAB images. Good agreement was found between RAB and FMI dips.

Dip correlation during drilling proved useful on subsequent California wells. Many have complex structures, and the absence of clear lithologic markers during drilling means that the structural position of wells may become uncertain. Currently, RAB image data are downloaded when drillpipe is pulled out of the hole for a new bit and dips are subsequently calculated. The data are used to determine if the well is on course for the highly fractured target area. 


Tuesday, August 6, 2019

Resistivity While Drilling - Images from the String

Resistivity measurements made while drilling are maturing to match the quality and diversity of their wireline counterparts. Recent advances include the development of multiple depth-of-investigation resistivity tools for examining invasion profiles, and button electrode tools capable of producing borehole images as the drillstring turns. 

It is hard to believe that logging while drilling (LWD) has come such a long way over the last decade. In the early 1980s, LWD measurements were restricted to simple resistivity curves and gamma ray logs, used more for correlation than formation evaluation. Gradually, sophisticated resistivity, density and neutron porosity tools have been added to the LWD arsenal. With the advent of high-deviation, horizontal and now slim multilateral wells, LWD measurements often provide the only means of evaluating reservoirs. The quality and diversity of LWD tools have continued to develop quickly to meet this demand. Today, applications include not only petrophysical analysis, but also geosteering and geological interpretation from LWD imaging. This article focuses on the latest LWD resistivity tools - the RAB Resistivity-at-the-Bit tool and the ARC5 Array Resistivity Compensated tool - and the images they produce.

 Geology From the Bit

Simply stated,  resistivity tools fall into two categories: laterolog tools that are suitable for logging in conductive muds, highly resistivity formations and resistive invasion; and induction tools which work best in highly conductive formations and can operate in conductive or nonconductive muds. The RAB tool falls into the first category although, stricly speaking, it is an electrode resistivity tool of which laterologs are one type. 

The RAB tool has four main features: 
  • toroidal transmitters that generate axial current- a technique highly suited to LWD resistivity tools
  • cyclindrical focusing that compensates for characteristic overshoots in resistivity readings at bed boundaries, allowing accurate true resistivity Rt determination and excellent axial resolution
  • bit resistivity that provides the earliest indication of reservoir penetration or arrival at a casing or coring point - also known as geostopping
  • azimuthal electrodes that produce a borehole image during rotary drilling.

This last feature allows the RAB tool to be used for geologic interpretation.

 Three 1 inch diameter buttons are mounted along the axis on one side of the RAB tool. Each button monitors radial current flow into the formation. As the drill string turns, these buttons scan the borehole wall, producing 56 resistivity measurements per rotation from each button. The data are processed and stored downhole for later retrieval when RAB tool is returned to the surface during a bit change. Once downloaded to the wellsite workstation, images can be produced and interpreted using standard geological applications like StructView Geoframe structural cross section software. 

Wellsite images allow geologist to quickly confirm the structural position of the well during drilling, permitting any necessary directional changes. Fracture identification helps optimize well direction for maximum production.

Tuesday, July 30, 2019

Mapping Porosity in Malaysia

Once thought to be useful primarily in carbonate reservoirs because of a more recognizable porosity-acoustic impedance relationship, inversion for porosity mapping has also proven powerful in sand reservoirs. PETRONAS Carigali, the upstream operating arm of the Malaysian national oil company, has used seismic inversion to optimize drilling locations in the Dulang West field in the Malay basin of the South China Sea.

The Dulang field has an estimated 850 million barrrels original oil in place (OOIP). In the first stage of development, more than 100 wells were drilled in the central area of the faulted anticlinal structure, producing from an oil and gas column of up to 150 m [492 ft] of stacked sandstones. The next stage of development focuses on the Dulang West portion, in which plans call for 25 wells from a 32-slot platform.

The four delineation wells indicate a reservoir too complex to understand from well data alone.The main reservoirs are fine-grained, discontinuous sands interbedded with shales and coals. The sand bodies are preferentially oriented, suggesting permeability anisotropy on the scale of the field. Porosity, permeability and their relationship to each other show great variability - for example, permeability can vary from 50 to several hundred millidarcies for a median porosity of 25%. In the central area developed earlier, close well spacing permitted property mapping from logs. But in Dulang West, engineers have relied on inversion of the 3D seismic data to extend information contained in the delineation wells to map porosity across the field.

After the poststack seismic and log data were tied at the right depths and inverted for acoustic impedance, log properties were tested for their correlation with the AI values at the respective well locations using the Log-Property Mapping module of the RM Reservoir Modeling software. Only porosity was found to correlate significantly with acoustic impedance, with a trend similar to that of the chalks of the East Hod field. Extending the log porosity values away from the four wells using the seismic inversion results as a guide produced a reservoir porosity map.


An integrated assessment of porosity and structure allowed interpreters to propose drilling locations. Areas of higher porosity in the south were deemed more promising than lower-porosity areas in fault block to the north. The well prognosis module of the RM system allowed several potential sites to be quickly investigated for reservoir quality and likely reserves.

The reservoir model built from the seismic data included not only the traditional aspect of reservoir structure, but also the total volume of porosity in each volume element of the seismic cube. This model was scaled up for input to a fluid-flow simulator. Permeability was distributed throughout the model by applying a porosity-permeability transform to the seismically guided porosity map. The new model provided a better estimation of production over a simulated seven-year period than that obtained by other methods.

In addition, areas of high acoustic impedance were interpreted to be shaly or to have poor reservoir development, enabling better placement of planned wells. Recent appraisal drilling southeast of well 6G-1.3 , testing oil potential downdip of gas inferred from an especially low AI anomaly, encountered 18 m [59 ft] of good quality, 18% porosity gross sand. Althought the sand was wet, agreement with the model was good, with 18.8 m [62 ft] and 19% porosity predicted. Two development wells, D1 and D2, further demonstrate the predictive power of the method. 


In some environments, seismic reflection amplitude variation with offset (AVO) can be used as a reservoir management tool to indicate hydrocarbon extent. The AVO technique relies on the observation - backed up by physics- that pore fluid imprints a signature on the amplitude of a seismic reflection. To see this signature, seismic data must be viewed at different angles of reflection. Depending on the type of pore fluid in the juxtaposed rock layers, the amplitude of the reflection may increase, decrease , or remain constant as the  as the reflection angle at the boundary increases. The incident angle of the seismic wave can be expressed in terms of offset, or distance , between seismic source and receiver - a congruent quantity more easily measured than an angle at some depth.

A common way to use AVO to characterize reservoirs is to identify a hydrocarbon AVO signature- for example, the AVO response of a gas reservoir- and comb the 3D seismic volume for other areas with similar signatures. This can result in discoveries of bypassed hydrocarbon as well as extension or delineation of existing reservoirs. The practice assumes that lithology does not have enough lateral variation to affect the seismic amplitudes, so that all AVO effects are due to changes in pore fluid type. The seismic data must be processed to preserve relative amplitudes, and also must be analyzed before stacking. 

Some lithologies show less obvious AVO sensitivity to pore fluid change than others. Carbonates and low-porosity sandstones tend to have less evident AVO signatures than high-porosity sandstones, and special care must be taken in applying the technology in these areas.

In an example from the mature BK field in the Gulf of Mexico, the successful incorporation of AVO analysis helped Oryx Energy Company engineers identify extensions of the reservoir that might have gone undrilled. The quality of the AVO results convinced management to free up money for drilling that had been allocated elsewhere.

The BK field lies off the flank of a shallow salt and shale diaper in 5 m of water near the Lousiana Gulf Coast. The reservoir, discovered in the late 1940s, has produced 300 billion cubic feet (Bcf) of gas. The map of the 5000-m [16,400-ft] deep structure had ben constructed primarily with well control, and the new 78-km2 survey, designed to provide incremental structural and stratigraphic information, changed the structural map significantly.

AVO analysis was introduced to better delineate the gas reservoir and reduce risk in choosing drilling locations. The analysis required a seismic cube for two different families of offsets. Data processing followed the same sequence as for the full 3D cube, except the data were separated into a near offset volume with offset ranges from zero to 3800 m and a far offset volume with offset from 3800 to 5800 m. 

Forward modeling using logs from producing wells indicated the gas zones have an AVO signature of amplitude increasing with offset. Interpretation consisted of finding other areas in which the near-offset volume has low amplitudes and the far-offset volume has higher amplitudes. 

The technique is demonstrated on a pair of seismic lines exctracted from the 3D volume. The AVO signature on Line 1215 at the gas-producing well BK-15 is the standard to which Line 1235 is compared to determine the likelihood of hitting gas at the proposed location BK-16. A color-coding system was devised to discriminate increasing AVO trends from decreasing ones. Results of the analysis show the BK-16 location to be similar to, and perhaps even more promising than, the producer BK-15. 

Initial production from the BK-16 well was 15.4 MMcf/D and 210 barrels of condensate per day from 25 m [82 ft] of 20% porosity sand. Sand quality is better than that found in the BK-15 well, refuting speculation that sand quality degrades to the northwest. And following the BK-16 well, two additional successful wells have been drilled within the region of AVO gas signature.

Tuesday, July 23, 2019

Seismic Tools for Reservoir Management

Reservoir engineers,geophysicists, geologist and managers agree that the 3D seismic technique can shed light on reservoir structure. But there's more to seismic than faults and layers: with the right handling, seismic data can predict rock and fluid properties across the whole field. Here's a look at some of the powerful probes in the seismic toolbox- inversion, AVO, 3D visualization and time-lapse surveys. 

Oil and gas companies large and small are relying on 3D seismic data to better delieate fields and identify new reserves. Operating companies have quantified and documented the value a 3D survey can add to an exploration or development project, compared to 2D survey. These testimonials describe the key role seismic images play in revealing reservoir locations and structures and the importance of using the information early in the life of a field to derive maximum benefit. 

But some companies are asking more of their 3D seismic surveys, demanding knowledge beyond- in fact between- reflections, and getting it. A new science of reservoir geophysics is emerging to provide this additional information to reservoir engineers. At the heart of the matter are reservoir geophysicist, who rely on high-quality 3D surveys- available through advances in acquisition, processing and interpretation techniques - for complete volume coverage of the reservoir. High-resolution borehole seismic surveys help fuse the surface seismic with log and core data to allow log properties such as lithology, porosity and fluid type to be mapped field-wide. With this more complete understanding of the reservoir, production engineers can optimize development and recover additional reserves. This article reviews case studies of four techniques that show promise- inversion, amplitude variation with offset (AVO), 3D visualization and time-lapse monitoring. 


Inversion is one of the foundations upon which reservoir geophysicist are building tools to make seismic information more useful to engineers. Inversion is so named because it acts as the inverse of forward modeling. Forward modeling takes an earth model of layers with densities and velocities, combines this with a seismic pulse, and turns out a realistic seismic trace- usually called a synthetic. Inversion takes a real seismic trace, removes the seismic pulse, and delivers an earth model of acoustic impedance (AI) , or density times velocity, at the trace location. Seismic inversion can be posed as a problem of obtaining an earth model for which the synthetic best fits the observed data. 

The simplest earth models contain layers with densities and compressional velocities, but more elaborate inversions yield models with shear velocities as well. Ideally, inversions combine surface seismic, vertical seismic profile (VSP), sonic and density log data. 

The main use of inversion for reservoir management comes through log-property mapping: the seismically derived AI values are tested for correlation with logs at the well location- porosity , lithology , water saturation, or any attribute that can be found to correlate. These log properties are then extrapolated throughout the inverted 3D seismic volume using the lateral variation of seismically derived AI to guide the process. 

Adequately processed seismic data are a must for inversion, but the optimum processing required to prepare data for inversion is the subject of much debate, as is the optimal inversion calculation itself. Numerous processing chains have been developed. A workshop was held recently to define the ultimate processing scheme, but to the surprise of the participants, no one method proved best. The trait that sets inversion apart from the standard processing chain for structural interpretation is the need for preservation of true relative amplitudes. Changes in trace amplitude from one location to another may reveal porosity or other formation property variations, but these amplitude changes are subtle and may be obliterated by conventional processing.

Inversion can be performed before or after the seismic traces have been stacked- summed to create a single trace at a central location- but care must be taken to ensure that stacking does not alter amplitudes. In some cases, such as regions where seismic reflection amplitudes vary with angle of incidence at the reflector, stacking does not preserve amplitudes, and inversion must be performed prestack. Only examples of poststack inversion results are presented in this article. 

The simplest inversion scheme derives relative acoustic impedance changes for one seismic trace by computing a cumulative sum of the amplitudes in the trace. The gradual trend of increasing AI with depth- invisible to seismic waves- is taken from density and cumulative sonic travel times, and added to the relative AI results.

Porosity Mapping in the Hod Field Chalks

Amoco Norway in Stavanger has drawn upon seismic inversion followed by porosity mapping as an aid to managing the development of the Hod field, the southern-most in the trend of chalk oil fields in the Norwegian sector of the North Sea. The two separate oil-filled anticlinal structures in the field - West and East Hod- were discovered in 1974 and 1977, respectively. However, reservoir uncertainties were not resolved by appraisal drilling, and marginal economics delayed production until 1990. Total estimated original reserves for the field are 66.9 million barrels of oil equivalent (BOE) , of which 94% are attributed to East Hod. An unmanned production platform is tied to the Valhall facilities to the north.

The primary reservoir interval at East Hod comprises allocthonous- reworked and redeposited- chalks of the Tor formation. The 2/11-A2 well encounters a prime chalk reservoir section, with 90 m [295 ft] of Tor formation showing porosities of up to 50%. Although East Hod is associated with a pronounced anticlinal closure, oil is trapped not only structurally, but also stratigraphically. Moveable oil has been observed below the established spillpoint, with reservoir distribution controlled by a combination of depositional, structural and diagenetic factors. The complex interplay between these factors results in a highly variable chalk reservoir. 

The top chalk surface represents an erosional unconformity that exposes a variety of chalk types from the Ekofisk, Tor and Hod formations to the overlying Paleocene shale seal. Well data show that chalks contributing to the top chalk seismic event have porosities ranging from 20 to 50% , with impedances ranging from 30,000 ft/sec x g/cm3 to 10,000 ft/sec x g/cm3. The high-quality reservoir rocks exhibit a decrease in acoustic impedance compared to the relatively uniform acoustic impedance of the overlying shale, while nonreservoir chalks show an increase. Therefore the acoustic properties of the chalk exert the primary influence on the amplitude of seismic reflections, making it possible to develop an effective method for mapping the reservoir extent and quality from inverted posstack seismic data.

Various 2D and 3D seismic inversion and porosity mapping techniques have been successfully applied in the area. Because of the combination of the great range in chalk impedance, and its predictable dependance on porosity, the results of most inversion techniques establish similar porosity trends, with the differences to be found in small details and absolute porosity values. 

The first 3D porosity mapping at Hod field was carried out using the Log-Property Mapping modole of the RM Reservoir Modeling system. Vertical well 2/11-3, with its excellent tie to the surface seismic data, was used as the key well to calibrate the inversion. The other wells also provided input to the low-frequency AI model and calibration of AI to porosity. 

This mapping supports the presence of a zone of high porosity beyond the limit of the East Hod structural closure.Subsequent drilling in this area has confirmed the inversion predictions of commercial porosity, and a horizontal producing well is currently draining the area which now represents a proven extension of the Hod field.

An ever increasing functionality and quality of applications are available for this type of reservoir characterization. An example of a significant refinement to the process used in the Hod field area is a scheme called space-adaptive wavelet processing. Applied as a precursor to inversion, this process integrates information from many wells to ensure that seismic data with a common, broadband, zero-phase wavelet are input to the inversion. The resulting improvement in the resolution of the inversion and subsequent interpretation have allowed porosity mapping from seismic to become a standard part of the chalk reservoir management process, and a primary means of identifying and quantifying the potential for extensions to the field or separate accumulations nearby.

Monday, July 15, 2019

Permanent Monitoring- Looking at Lifetime Reservoir Dynamics

Permanent monitoring systems measure and record well performance and reservoir behavior from sensors placed downhole during completion. These measurements give engineers information essential to dynamically manage hydrocarbon assets, allowing them to optimize production techniques, diagnose problems, refine field development and adjust reservoir models. 

Reservoir development and management traditionally rely on early data gathered during short periods of logging and testing before wells are placed on production. Additional data may be acquired several months later, either as a planned exercise or when unforeseen problems arise. Such data acquisition requires well intervention and nearly always means loss of production, increased risk, inconvenience and logistical problems, and may also involve the additional expense and time of bringing a rig onto location. 

Permanent monitoring systems allow a different approach. Sensors are placed downhole with the completion string close to the heart of the reservoir. Modern communications provide direct access to sensor measurements from anywhere in the world. Reservoir and well behavior may now be monitored easily in real time, 24 hours a day, day after day, throughout the lifetime of the reservoir. Engineers can watch performance daily, examine responses to changes in production or secondary recovery processes and also have a record of events to help diagnose problems and monitor remedial actions, rather like monitors in a power plant's control room.

Most systems in operation record bottom hole pressure and temperature, but other measurements, such as downhole flow rate, are being introduced and may become common in the future. However, pressure and temperature provide dozens of beneficial applications. This article reviews the development of permanent monitoring, looks at applications with several examples and describes the hardware.

 Early Days

Permanent monitoring has its roots in the early 1960s on land wells in the USA. Pressure gauges were needed to monitor the performance of secondary recovery projects, such as waterfloods or artificial lift schmes, where they were required downhole for several weeks. In many cases, the only option available was to run a standard pressure gauge on the end of the completion string. The cable for power and data transmission was passed through an insulated connector in the Christmas tree, strapped to the outside of the tubing and then ported back inside the tubing just above the gauge leaving the bore free of any obstructions. Even though the hardware was simple by today's standards, these early examples proved invaluable to oil companies and showed the diverse use of and benefits from the pressure data gathered. 

 One example from 1962 is typical of the period. Henderson 6 was the second well completed by the Coronado Company in the Bell Sand of the Old Woman Anticline, Wyoming, USA. A permanent pressure gauge was placed below a conventional pump in a 2400-ft well for interference testing and to determine the productivity index. Initial bottomhole pressure (BHP) was 680 psi. 

The well produced 340 barrels of oil per day (BOPD) with a 60-psi drawdown, but quickly suffered from increasing water cut. Bottomhole pressure returned to 680 psi indicating complete water breakthrough - possibly by water coning. By modifying production and monitoring downhole pressure changes it quickly became apparent that the coning problem would not repair itself and that the well would have to undergo workover. Afterward the well was put back on production and, this time, the pressure gauge measurements were used to control drawdown to just 40 psi to prevent recurrence of water coning.

Other examples from the 1960s show how pressure gauges were used to monitor progress of secondary recovery fronts across fields, to check the operation of subsurface pumps, to provide reservoir data and to calculate individual well drainage during the life of the reservoir. 

The first permanent pressure gauge run by $$$ was for Elf in Gabon (Africa) in 1972 followed one year later by the first North Sea installation on Shell's Auk platform. These early systems were essentially adaptations of electric wireline technology. A standard strain pressure gauge was clamped to the tubing and ported to monitor tubing pressure. A stranded single-conductor logging cable was strapped to the outside of the tubing exiting at the wellhead. Data were recorded on a standard acquisition unit. 

Many early failures were caused by damage during installation or by cable problems at a later date - either by loss of electrical continuity or breakdown of insulation causing a short circuit. Statoil report that many cable failures occured at splices and now request splice-free cables. Detailed analysis , such as that performed by Petrobras on systems run in Brazil and the North Sea, shows how reliability has improved. More recently a detailed research and development project has resulted in development of a new generation permanent gauge and its associated components for even greater reliability. 

Present systems are engineered specifically for the permanent monitoring market and have a life expectancy of several years. Gauges have digital electronics designed for extended exposure to high temperature and undergo extensive design qualification life tests and strict quality checks during manufacture before being hermetically sealed. They are not designed for maintenance.

Cables for permanent installations are encased in stainless steel or nickel alloy pressure-tight tubing that is polymer-encapsulated for added protection. All connections are verified by pressure testing during installation.

Connections through tubing hanger and wellhead vary depending on the type of completion- subsea, platform or land but components are standard, tried and tested designs made in conjuction with the tubing hanger and wellhead manufacturers.

Data transmission and recording are tailored to oil company needs, and wherever possible industry standards are used so that signals may be integrated with other systems. For example, many subsea completions have memory modules called data loggers that record, for instance, wellhead pressure or the status of control values. Permanent gauge data may be fed to interface cards located in the data-logger so that data transfer may be executed in one step. 

Tuesday, May 28, 2019

Modeling Logs for Horizontal Well Planning and Evaluation

Horizontal wells can increase production rates and ultimate recovery, and can reduce the number of platforms or wells required to develop a reservoir. They can also help avoid water or gas breakthrough, bypass environmentally sensitive areas and reduce stimulation costs.

As exploration and development budgets tighten, companies are becoming more efficient by drilling fewer, well-placed holes. Reentry and multilateral wells are growing in number, along with short-radius wells. There are greater expectations and smaller margins for error in driling today's horizontal wells. 

Drilling horizontal wells presents formidable challenges. Planning trajectories, choosing fluids, steering, formation evaluation and completion- each stage is a huge task. Several stages-planning,steering and formation evaluation- benefit from combining the efforts of geologist, log analyst and directional drillers. 

A powerful partner in all these stages is forward modeling, or log simulation. Other industries are using simulation to help train pilots , model aircraft and automobile reliability and response, design buildings, test weapons, record music, predict weather- the list is endless. In the oil field, modeling helps make efficient use of logs in horizontal wells in two ways- first by predicting logging-while-drilling (LWD) tool response to guide directional drilling, and second by constraining formation evaluation when the conventional assumptions of a vertical well no longer hold. 

Directional drilling practice and technology have evolved to the point where , given a good plan, the target can be hit with high accuracy. The drill bit can be placed within a target the volume of an engineer's office at a depth and lateral offset of a few miles. Trajectories are becoming more complex as directional drillers push the technology to its limits in "designer" wells. To improve the odds of these wells hitting the target, they are carefully planned in two steps: definition of the target from maps and logs, then design of a wellbore trajectory to hit it. 

No plan, unfortunately, is foolproof. Uncertainties in the position of the target , combined with unpreditictability of structural and stratigraphic variations, even in developed fields, can cause directional drillers to lose their way. The chance of going astray declines significantly, however, with the use of real-time formation evaluation logs and comparison of the logs with modeled cases to gauge the position of the tool within the sequence of beds. The INFORM Integrated Forward Modeling program provides an interface for building a formation model and simulating log response, allowing drillers to anticipate what's ahead. We look first at modeling for horizontal well planning, then explore how the INFORM system facilitates postdrilling visualization of LWD and wireline logs in horizontal wells.  

Model First, Then Drill

Often the objective of drilling a horizontal well is to penetrate the reservoir but stay close to a caprock shale or gas-oil contact- to drill parallel to a boundary or a contrast in material properties- for thousands of feet. Such a viewing angle is unusal for electromagnetic tools, the tools most commonly used for steering. Other measurements, such as gamma ray and density, are also affected by the horizontal geometry, giving an asymmetric response as they lie against the floor of the borehole. 

Because most resistivity tools probe several feet into the formation, they are affected by resistivity inhomogeneities in the vicinity of the well and even ahead of the drill bit. This early warning feature is beneficial to directional drillers, who harness it to steer wells into target layers or away from problem zones before they are encountered by the bit. This "proximity effect" can be accurately modeled during predrilling planning to provide a road map for drilling.

In a planning example from the North Sea, Jim White of Schlumberger Wireline & Testing in Aberdeen, Scotland, used log modeling to demonstrate the feasibility of landing the well in a thin sand and avoiding high-resistivity , calcite-cemented , tight streaks. Forward modeling computed the response of the CDR Compensated Dual Resistivity tool with its two depths of investigation- shallow from the phase shift measurement and deep from the attenuation log. When the wellbore came to within 3 ft of the calcite zone, the modeled attenuation and phase shift curves crossed, because the deeper-reading attenuation measurement senses the high-resistivity calcite. 

The CDR logs acquired when the well was drilled corroborated the modeled predictions. Based on the simulations, the signature of the lower boundary- the deep reading crossing over the shallow was recognized while drilling, and the well was steered away. Had the well entered the cemented zone, drillers estimated they would have spent several days trying to get back on target. 

Geologist from Chevron Niugini are using INFORM forward modeling to plan and geosteer horizontal wells in the Iagifu Hedinia field, within the Southern Highlands Province of Papua New Guinea. Located in Papuan Fold and Thrust belt, this field is part of a double anticline complex in the Hedinia thrust sheet. The major oil reservoir is the Lower Cretaceous Toro sandstone. Within the Toro, the hydrocarbon accumulation consists of an oil band up to 218 meters [ 715 ft] thick overlain by a gas cap. Gas cap expansion and gravity drainage are the major drive mechanisms for the field, with support from the Toro aquifer making a minor contribution.

Development well planning and drilling are complicated by the complex fold geometry. Unfortunately, the rugged karst topography created in the Darai Limestone at surface prohibits the acquisition of usable seismic data. For predicting the subsurface reservoir geometry, geologist rely on surface geological mapping, side-scan radar imagery, dipmeter data and correlation logs from adjacent wells.

In order to maximize productivity and ultimate recovery from the horizontal wells, wells are programmed to be horizontal in the Toro oil reservoir at a level of 15 m [50 ft] above the oil-water-contact. This enables the wells to produce oil at lower solution gas/oil ratios (GOR) and should delay breakthrough from the advancing gas front. 

During drilling to the Toro objective, the landing phase is critical to the success of the horizontal well program. With an unstable Alene shale section overlying the Toro, it is important to minimize the amount of horizontal section drilled before encountering the top Toro. Conversely, encountering the Toro during the build section of the well course, before reaching horizontal, can result in loss of productive interval since this hole section may be too close to the current gas-oil contact and would not be perforated. The Alene is drilled with mud weights in the range of 12 to 14 ppg, while the current reservoir pressure in the Toro are in the 4.5 to 5.5 ppg equivalent range. To prevent loss circulation problems and possible loss of the hole, it is necessary to identifiy the top of the Toro casing point before penetrating more than 1.5 to 3 m [ 5 to 10 ft] of the sandstone. 

An accurate predictive model of the Toro anticlinal geometry resulting from recognition of overlying stratigraphic markers while drilling -as well as the ability to determine the structural attitude of these layers - increases the probability for a successful landing phase. With INFORM processing, a model of stratigraphic interval above the target can be built using well logs and dipmeter data from nearby wells along with geological structure models developed for the planned horizontal well. LWD responses for the potential range of structural dips within a particular area of the anticlinal fold can be simulated. 

As the well course builds to horizontal, the geosteering specialist and geologist correlate major stratigraphic LWD markers and estimate the structural dip of a stratigraphic unit in the plane of the well course by optimizing the match between the LWD curves and the model log curves. The calculated structural dip estimates are compared to those in the geologist's predicted fold geometry cross-sectional model. The new dips are then used to correct the subsurface structure model and revise the top target coordinates.

During the planning for the first well, IHT-1, gamma ray and resistivity logs from three nearby wells were used to create a model for computing CDR responses for the full range of possible structural dip magnitudes along potential well trajectories. The responses were stored in a relative angle data base. The programmed well course was oblique to the strike of the Toro in this area of the Iagifu anticline, and was designed to be horizontal 15 m above the oil-water contact. This entry point is depth-constrained by the predicted oil-water contact level, and laterally constrained by the projected position of the Toro entry point, determined by projecting the Toro structural dip away from well control points higher on the anticlinal flank. The kick-off depth and deviation angle build rate depend on knowing this entry position. (picture)

During the drilling of well IHT-1, a computer structure model with sections of 6 degree and 8 degree apparent dip was constructed with the INFORM system, using data transmitted via satellite link. The stratigraphic horizon boundaries, dip magnitude and true vertical depth of each section was determined from the match between the measured CDR logs and the modeled logs. This match is consistent down to the Toro, indicating the structural dip model is a good representation of the actual Toro subsurface structure. 

Typically the CDR tool, producing characteristic horns at high-angle bed boundaries, is run to land wells. FOr the IHT-1 well bottomhole assembly configurations, however, this tool is located 18 m [60 ft] behind the bit. To precisely locate the 9 5/8 -inch casing setting depth at the top Toro, the last bit trip is run with the Geosteering tool, an instrumented steerable downhole motor with two resistivity sensors.

 The primary purpose of the Geosteering tool is to drill the horizontal drainhole and confirm that the well is above the oil-water contact in each sand. Normally Geosteering tool data are not acquired in the upper 6 to 9 m [20 to 30 ft] of the Toro, until the tool signal receiver clears casing. Because of mechanical problems, the 9 5/8 in. casing in IHT-1 ended 27 m [90 ft] above the Toro. This allowed the Geosteering tool to acquire data across the shale-sandstone resitivity contrast at the top of the Toro.

Unexpectedly, IHT-1 entered the dipping Toro reservoir beneath a present-day oil-water contact at 8741 ft true vertical depth (TVD). The contact was apparently 15 to 18 m [50 to 60 ft] shallower than predicted, probably due to pressure depletion of the upper Toro reservoir in this area of the field. The bit resistivity gave an immediate indication of water-saturated Toro. The planned trajectory was modified to build angle to greater than 90 degrees in an upward trajectory, crossing the oil-water contact from underneath. During drilling in the mid-Toro, the well encountered lost fluid circulation problems, possibly at a fault or fracture zone. With sudden unloading of the borehole, collapse occured in the unstable shale openhole section above the Toro, and the hole was lost.

IHT-1A, a sidetrack designed to take a parallel well path, was planned using the structural attiiude data and oil-water contact information from IHT-1. A short 30.5 -m [100 ft] , 8 1/2 inch pilot hole was drilled at the end of the buildup section with the Geosteering tool to "geostop" exactly on the shale-sandstone reservoir boundary. This hole was enlarged, and the 9 5/8 inch casing set just on the reservoir top. As expected, dips were close to those in IHT-1, and the well was landed within the Toro oil leg as planned, 15 m above the present day oil-water contact. It continued for 427 m [1400 ft] across the three main Toro reservoir sandstone members. The well was completed as an oil well, producing more than 10,000 stock tank barrels of oil per day, at solution GOR. 

Another well, IHT-2, on the same structure, encountered 55 degree dips, much steeper than the 22 degree anticipated. These were successfully modeled and the well path modified to hit the target.

After drilling, Model Again

Once drilled and logged, horizontal wells continue to pose challenges in visualization and formation evaluation. Log simulation can help verify a formation model or the location of  a well in space, to use for future development planning and quality control. More importantly, modeling helps untagle true formation properties such as formation fluid resistivity, Rt , and water saturation, Sw from the melange of shallow and deep responses of while-drilling and wireline tools.

In the Gulf of  Mexico, Lee Lehtonen at Mobil Exploration and Producing in New Orleans Lousiana, USA tested simulation to validate the model of a horizontal well designed to tap multiple compartments in a faulted reservoir. The horizontal well was to traverse four fault blocks.

Pay in the first and fourth blocks would be isolated by enough shale to allow setting external packers. In this case, INFORM modeling showed how LDW porosity logs could be used to distinguish a change in formation properties associated with faulting from changes encountered in a new stratigraphic layer. 

The ADN Azimuthal Density Neutron tool measures-while drilling- bulk density, ultrasonic standoff, photoelectric factor and neutron porosity. Magnetometers continously measure tool orientation , and results are distributed into readings above, below and to each side of the borehole. This allows discrimination of the orientation of planes of porosity and density discontinuity in the formation. 

In the Mobil well, CDR and ADN data were recorded into memory while drilling, and data were brought uphole with each bit change. These logs were compared with logs simulated using a formation model built from the known structure and pilot well logs. During the fifth bit run, the density tool encountered a shale-sand contact. Examination of the density porosity logs shows that the average and bottom quadrant curves both detect the interface at the same measured depth, XX340 ft. Comparing the acquired and simulated logs shows the contact can be modeled as a fault separating shale from sand.